**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C.  20549**

 

**FORM 10-Q**

 
| **ý**                                                                                                                                                                                                                             | **QUARTERLY REPORT PURSUANT TO  SECTION 13 OR 15(d)  OF THE SECURITIES EXCHANGE ACT OF 1934**  |   |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------------------------------------------------------------------------------------------|--------|
|                                                                                                                                                                                                                                   |
| **For the quarterly period ended June 30, 2003**                                                                                                                                                                                  |
|                                                                                                                                                                                                                                   |                                                                                           |
| **OR**                                                                                                                                                                                                                                 |
|                                                                                                                                                                                                                                   |
| **o**                                                                                                                                                                                                                                  | **TRANSITION REPORT PURSUANT TO  SECTION 13 OR 15(d)  OF THE SECURITIES EXCHANGE ACT OF 1934** |   |
|                                                                                                                                                                                                                                   |
| **For the transition period from                  to                ** |
|                                                                                                                                                                                                                                   |                                                                                           |
| **Commission file number 1-10934**                                                                                                                                                                                                     |
|                                                                                                                                                                                                                                        |                                                                                                |        |  |

 

**ENBRIDGE ENERGY PARTNERS, L.P.**

(Exact name of registrant asspecified in its charter)

 

| **Delaware**                                                     |   | **39-1715850**                        |
|------------------------------------------------------------------|--------|---------------------------------------|
| (State or other jurisdiction  of  incorporation or organization) |   | (I.R.S. Employer  Identification No.) |
|                                                             |   |                                  |
| **1100 Louisiana  Suite 3300Houston, TX  77002**            |
| (Address of principal  executive offices and zip code)           |
|                                                             |   |                                  |
| **(713) 821-2000**                                               |
| (Registrant’s telephone  number, including area code)       |

 

----

 

Indicate by check mark whether the registrant (1) has filed all reportsrequired to be filed by Section 13 or 15(d) of the Securities Exchange Act of1934 during the preceding 12 months (or for such shorter period that theregistrant was required to file such reports), and (2) has been subject to suchfiling requirements for the past 90 days.

Yes ý    No o

 

Indicate by checkmark whether the registrant is an accelerated filer(as defined in Rule 12b-2 of the Exchange Act

Yes ý    No o

 

The Registrant had 35,166,134 Class A Common Units outstanding as ofAugust 14, 2003.

 

 

----

 

**TABLEOF CONTENTS**

 
| **PART I.  FINANCIAL INFORMATION** |
|------------------------------------|
|                               |
| **Item 1.**                        | Financial Statements |
|                               | Consolidated Statements of Income  for the three and six month periods ended June 30, 2003 and 2002 |
|                               |   |
|                               | Consolidated Statements of Comprehensive  Income  for the three and six month periods ended June 30, 2003 and 2002 |
|                               |   |
|                               | Consolidated Statements of Cash Flows  for the six month periods ended June 30, 2003 and 2002 |
|                               |   |
|                               | Consolidated Statements of Financial  Position  as of June 30, 2003 and December 31, 2002 |
|                               |   |
|                               | Consolidated Statement of Partners’ Capital  for six month period ended June 30, 2003 |
|                               |   |
|                               | Notes to Consolidated Financial Statements |
|                               |   |
| **Item 2.**                        | Management’s Discussion and Analysis of  Financial Condition and Results of Operations |
|                               |   |
| **Item 3.**                        | Quantitative and Qualitative Disclosures  About Market Risk |
|                               |   |
| **Item 4.**                        | Controls and Procedures |
|                               |   |
| **PART II. OTHER INFORMATION**     |
|                               |   |
| **Item 1.**                        | **Legal Proceedings** |
|                               |   |
| **Item 6.**                        | Exhibits and Reports on Form 8-K |
|                               |   |
| **Signature**                      |   |
|                               |   |
| **Exhibits**                       |

 

*This Quarterly Report on Form 10-Q contains forward-lookingstatements. These forward-looking statements are identified as any statementthat does not relate strictly to historical or current facts. They use wordssuch as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,”“intend,” “may,” “plan,” “position,” “projection,” “strategy” or “will” or thenegative of those terms or other variations of them or by comparableterminology. In particular, statements, expressed or implied, concerning futureactions, conditions or events or future operating results or the ability togenerate sales, income or cash flow or to make distributions areforward-looking statements. Forward-looking statements are not guarantees ofperformance. They involve risks, uncertainties and assumptions. Future actions,conditions or events and future results of operations may differ materiallyfrom those expressed in these forward-looking statements. Many of the factorsthat will determine these results are beyond the ability of Enbridge EnergyPartners, L.P. (the “Partnership”) to control or predict.  For additional discussion of risks,uncertainties and assumptions, see the Partnership’s Annual Report on Form 10-Kfor the fiscal year ended December 31, 2002.*

 

1

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***PART I******- FINANCIAL INFORMATION***

 

***ITEM 1******. FINANCIAL STATEMENTS***

 

***ENBRIDGE ENERGYPARTNERS, L.P.***

***CONSOLIDATEDSTATEMENTS OF INCOME***

 
|                                                           |   | **Three  months ended  June 30,** | ** ** | **Six months  ended  June 30,** | ** ** |
|----------------------------------------------------------------|--------|----------------------------------------|------------|--------------------------------------|------------|
| **(unaudited;  dollars in millions, except per unit amounts)** |   | **2003**                               |       | **2002**                             | ** ** | **2003** | ** ** | **2002** | ** ** |
|                                                           |   |                                   |       |                                 |       |   |   |   |   |
| Operating revenue                                              |   | $                                      | 755.3      |                                 | $          | 223.1 |   | $ | 1,651.4 |   | $ | 404.9 |   |
|                                                           |   |                                   |       |                                 |       |   |   |   |   |
| Operating Expenses                                             |   |                                   |       |                                 |       |   |   |   |   |
| Cost of natural gas                                            |   | 623.4                                  |       | 130.8                                |       | 1,376.9 |   | 220.4 |   |
| Operating and administrative                                   |   | 52.3                                   |       | 30.9                                 |       | 104.9 |   | 58.7 |   |
| Power                                                          |   | 13.0                                   |       | 12.4                                 |       | 25.7 |   | 26.0 |   |
| Depreciation and amortization *(Note 7)*                       |   | 23.5                                   |       | 18.6                                 |       | 46.9 |   | 36.9 |   |
|                                                           |   |                                   |       |                                 |       |   |   |   |   |
|                                                           |   | 712.2                                  |       | 192.7                                |       | 1,554.4 |   | 342.0 |   |
|                                                           |   |                                   |       |                                 |       |   |   |   |   |
| Operating income                                               |   | 43.1                                   |       | 30.4                                 |       | 97.0 |   | 62.9 |   |
|                                                           |   |                                   |       |                                 |       |   |   |   |   |
| Interest and other income (expense)                            |   | 1.8                                    |       | 0.1                                  |       | 1.8 |   | 0.2 |   |
| Interest expense                                               |   | (21.6                                  | )          | (13.5                                | )          | (42.9 | ) | (28.2 | ) |
| Minority interest                                              |   | —                                 |       | (0.2                                 | )          | — |   | (0.4 | ) |
|                                                           |   |                                   |       |                                 |       |   |   |   |   |
| Net income                                                     |   | $                                      | 23.3       |                                 | $          | 16.8 |   | $ | 55.9 |   | $ | 34.5 |   |
|                                                           |   |                                   |       |                                 |       |   |   |   |   |
| Net income per unit (*Note 2*)                                 |   | $                                      | 0.39       |                                 | $          | 0.39 |   | $ | 1.01 |   | $ | 0.82 |   |
|                                                           |   |                                   |       |                                 |       |   |   |   |   |
| Weighted average units outstanding  (millions)                 |   | 46.8                                   |       | 35.2                                 |       | 45.7 |   | 34.4 |   |

 

The accompanying notes to theConsolidated Financial Statements are an integral part of these statements.

 

2

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***ENBRIDGE ENERGYPARTNERS, L.P.***

***CONSOLIDATEDSTATEMENTS OF COMPREHENSIVE INCOME (LOSS)***

 
|                                                                         |   | **Three  months ended  June 30,** | ** ** | **Six months  ended  June 30,** | ** ** |
|------------------------------------------------------------------------------|--------|----------------------------------------|------------|--------------------------------------|------------|
| **(unaudited;  dollars in millions)**                                        |   | **2003**                               |       | **2002**                             | ** ** | **2003** | ** ** | **2002** | ** ** |
|                                                                         |   |                                   |       |                                 |       |   |   |   |   |
| Net income                                                                   |   | $                                      | 23.3       |                                 | $          | 16.8 |   | $ | 55.9 |   | $ | 34.5 |   |
|                                                                         |   |                                   |       |                                 |       |   |   |   |   |
| Unrealized loss on derivative financial  instruments                         |   | (41.9                                  | )          | (3.6                                 | )          | (63.6 | ) | (18.1 | ) |
|                                                                         |   |                                   |       |                                 |       |   |   |   |   |
| Change associated with ineffectiveness of  current period hedge transactions |   | 0.5                                    |       | —                               |       | 0.5 |   | — |   |
|                                                                         |   |                                   |       |                                 |       |   |   |   |   |
| Comprehensive income (loss) *(Note 6)*                                       |   | $                                      | (18.1      | )                                    | $          | 13.2 |   | $ | (7.2 | ) | $ | 16.4 |   |

 

The accompanying notes to theConsolidated Financial Statements are an integral part of these statements.

 

3

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***ENBRIDGE ENERGYPARTNERS, L.P.***

## ***CONSOLIDATED STATEMENTS OF CASHFLOWS***

 
| **(unaudited;  dollars in millions)****Six months ended June 30,**        |   | **2003** | ** ** | **2002** | ** ** |
|--------------------------------------------------------------------------------|--------|----------|------------|----------|------------|
|                                                                           |   |     |       |     |       |
| Cash provided by operating activities                                          |   |     |       |     |       |
| Net income                                                                     |   | $        | 55.9       |     | $          | 34.5 |   |
| Adjustments to reconcile net income to cash  provided by operating activities: |   |     |       |     |       |
| Depreciation and amortization                                                  |   | 46.9     |       | 36.9     |       |
| Hedge transactions ineffectiveness *(Note 6)*                                  |   | 0.5      |       | —   |       |
| Payments made upon termination of  derivative *(Note 6)*                       |   | (6.1     | )          | —   |       |
| Other                                                                          |   | 0.3      |       | 0.2      |       |
| Changes in operating assets and  liabilities,  Receivables, trade and other    |   | (87.1    | )          | (20.9    | )          |
| Other current assets                                                           |   | (6.0     | )          | (3.2     | )          |
| General Partner and affiliates                                                 |   | (11.1    | )          | (15.1    | )          |
| Accounts payable and other                                                     |   | (9.7     | )          | 22.0     |       |
| Accrued gas purchases                                                          |   | 91.0     |       | —   |       |
| Interest payable                                                               |   | 2.7      |       | 0.3      |       |
| Property and other taxes                                                       |   | (1.7     | )          | (3.9     | )          |
|                                                                           |   |     |       |     |       |
| Cash provided by operating activities                                          |   | 75.6     |       | 81.0     |       |
|                                                                           |   |     |       |     |       |
| Investing activities                                                           |   |     |       |     |       |
| Repayments from affiliate                                                      |   | —   |       | 0.2      |       |
| Additions to property, plant and equipment                                     |   | (45.6    | )          | (102.6   | )          |
| Changes in construction payables                                               |   | (5.4     | )          | 2.4      |       |
| Asset acquisitions, net of cash acquired                                       |   | (0.4     | )          | (3.7     | )          |
|                                                                           |   |     |       |     |       |
| Cash used in investing activities                                              |   | (51.4    | )          | (103.7   | )          |
|                                                                           |   |     |       |     |       |
| Financing activities                                                           |   |     |       |     |       |
| 364-day facility                                                               |   | (132.0   | )          | 274.0    |       |
| Revolving credit facility                                                      |   | —   |       | (137.0   | )          |
| Three-year credit facility                                                     |   | (52.0    | )          | (7.0     | )          |
| Issuance of senior unsecured notes, net *(Note 5)*                             |   | 396.3    |       | —   |       |
| Loans from Enbridge Energy Company, Inc.,  net                                 |   | (316.0   | )          | (117.7   | )          |
| Proceeds from unit issuance, net *(Note 4)*                                    |   | 168.2    |       | 93.2     |       |
| Distributions to partners                                                      |   | (74.3    | )          | (67.3    | )          |
| Other                                                                          |   | (0.5     | )          | (1.8     | )          |
|                                                                           |   |     |       |     |       |
| Cash (used in) provided by financing  activities                               |   | (10.3    | )          | 36.4     |       |
|                                                                           |   |     |       |     |       |
| Net increase in cash and cash equivalents                                      |   | 13.9     |       | 13.7     |       |
|                                                                           |   |     |       |     |       |
| Cash and cash equivalents at beginning of  period                              |   | 60.3     |       | 40.2     |       |
|                                                                           |   |     |       |     |       |
| Cash and cash equivalents at end of period                                     |   | $        | 74.2       |     | $          | 53.9 |   |

 

The accompanying notes to theConsolidated Financial Statements are an integral part of these statements.

 

4

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***ENBRIDGE ENERGYPARTNERS, L.P.***

***CONSOLIDATEDSTATEMENTS OF FINANCIAL POSITION***

 
| **(unaudited;  dollars in millions)**                                                                         |   | **June 30,  2003** |    | **December 31,  2002** | ** ** |
|---------------------------------------------------------------------------------------------------------------|--------|-------------------------|---------|-----------------------------|------------|
|                                                                                                          |   |                    |    |                        |       |
| ***ASSETS***                                                                                                  |   |                    |    |                        | ** ** |
|                                                                                                          |   |                    |    |                        |       |
| Current assets                                                                                                |   |                    |    |                        |       |
| Cash and cash equivalents                                                                                     |   | $                       | 74.2    |                        | $          | 60.3 |   |
| Receivables, trade and other, net of  allowance for  doubtful accounts of  $3.4 in 2003 and $3.7 in 2002 |   | 305.1                   |    | 217.9                       |       |
| Other current assets                                                                                          |   | 25.6                    |    | 19.3                        |       |
|                                                                                                          |   | 404.9                   |    | 297.5                       |       |
|                                                                                                          |   |                    |    |                        |       |
| Property, plant and equipment, net                                                                            |   | 2,253.1                 |    | 2,253.3                     |       |
| Goodwill                                                                                                      |   | 239.3                   |    | 241.1                       |       |
| Other assets, net                                                                                             |   | 45.1                    |    | 43.0                        |       |
|                                                                                                          |   |                    |    |                        |       |
|                                                                                                          |   | $                       | 2,942.4 |                        | $          | 2,834.9 |   |
|                                                                                                          |   |                    |    |                        |       |
| ***LIABILITIES AND  PARTNERS’ CAPITAL***                                                                 |   |                    |    |                        |       |
|                                                                                                          |   |                    |    |                        |       |
| Current liabilities                                                                                           |   |                    |    |                        |       |
| Due to General Partner and affiliate                                                                          |   | $                       | 52.0    |                        | $          | 63.1 |   |
| Accounts payable and other                                                                                    |   | 92.2                    |    | 99.1                        |       |
| Accrued gas purchases                                                                                         |   | 233.1                   |    | 142.1                       |       |
| Interest payable                                                                                              |   | 9.7                     |    | 7.0                         |       |
| Property and other taxes payable                                                                              |   | 14.6                    |    | 16.3                        |       |
| Current maturities and short-term debt *(Note 5)*                                                             |   | 111.0                   |    | 31.0                        |       |
|                                                                                                          |   | 512.6                   |    | 358.6                       |       |
|                                                                                                          |   |                    |    |                        |       |
| Long-term debt *(Note 5)*                                                                                     |   | 1,146.7                 |    | 1,011.4                     |       |
| Loans from General Partner and affiliates                                                                     |   | 128.1                   |    | 444.1                       |       |
| Environmental liabilities                                                                                     |   | 5.6                     |    | 5.6                         |       |
| Deferred credits                                                                                              |   | 71.1                    |    | 23.2                        |       |
| Minority interest                                                                                             |   | —                  |    | 0.4                         |       |
|                                                                                                          |   | 1,864.1                 |    | 1,843.3                     |       |
|                                                                                                          |   |                    |    |                        |       |
| Partners’ capital                                                                                        |   |                    |    |                        |       |
| Class A common units (Units authorized and  issued – 35,166,134 in 2003 and 31,313,634 in 2002)          |   | 729.8                   |    | 604.8                       |       |
| Class B common units (Units authorized and  issued – 3,912,750 in 2003 and 2002)                         |   | 55.3                    |    | 48.7                        |       |
| i-units (Units authorized and issued –  9,673,843 in 2003 and 9,228,655 in 2002)                         |   | 350.0                   |    | 335.6                       |       |
| General Partner                                                                                               |   | 22.6                    |    | 18.8                        |       |
| Accumulated other comprehensive loss                                                                          |   | (79.4                   | )       | (16.3                       | )          |
|                                                                                                          |   | 1,078.3                 |    | 991.6                       |       |
|                                                                                                          |   |                    |    |                        |       |
|                                                                                                          |   | $                       | 2,942.4 |                        | $          | 2,834.9 |   |

 

The accompanying notes to the Consolidated Financial Statements are anintegral part of these statements.

 

5

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***ENBRIDGE ENERGYPARTNERS, L.P.***

***CONSOLIDATEDSTATEMENT OF PARTNERS’ CAPITAL***

 
| **(unaudited;  dollars in millions)**                          |   | **Units**  |   | **Amount** | ** ** |
|----------------------------------------------------------------|--------|------------|--------|------------|------------|
|                                                           |   |       |   |       |       |
| **Class A Units:**                                             |   |       |   |       |       |
| Beginning balance at December 31, 2002                    |   | 31,313,634 |   | $          | 604.8      |   |
| Net income allocation                                          |   | —     |   | 32.3       |       |
| Allocation of net proceeds from unit  issuance (*Note 4*)      |   | 3,852,500  |   | 150.6      |       |
| Distributions to partners                                      |   | —     |   | (57.9      | )          |
| Ending balance at June 30, 2003                           |   | 35,166,134 |   | $          | 729.8      |   |
|                                                           |   |       |   |       |       |
| **Class B Units:**                                             |   |       |   |       |       |
| Beginning balance at December 31, 2002                    |   | 3,912,750  |   | 48.7       |       |
| Net income allocation                                          |   | —     |   | 4.5        |       |
| Allocation of net proceeds from unit  issuance                 |   | —     |   | 9.3        |       |
| Distributions to partners                                      |   | —     |   | (7.2       | )          |
| Ending balance at June 30, 2003                           |   | 3,912,750  |   | $          | 55.3       |   |
|                                                           |   |       |   |       |       |
| **i-units:**                                                   |   |       |   |       |       |
| Beginning balance at December 31, 2002                    |   | 9,228,655  |   | 335.6      |       |
| Net income allocation                                          |   | —     |   | 9.5        |       |
| Allocation of net proceeds from unit issuance                  |   | —     |   | 4.9        |       |
| Distributions to partners                                      |   | 445,188    |   | —     |       |
| Ending balance at June 30, 2003                           |   | 9,673,843  |   | $          | 350.0      |   |
|                                                           |   |       |   |       |       |
| **General Partner:**                                           |   |       |   |       |       |
| Beginning balance at December 31, 2002                    |   | —     |   | 18.8       |       |
| Net income allocation                                          |   | —     |   | 9.6        |       |
| Allocation of net proceeds from unit  issuance                 |   | —     |   | (0.2       | )          |
| General Partner contribution                                   |   | —     |   | 3.9        |       |
| Distributions to partners                                      |   | —     |   | (9.5       | )          |
| Ending balance at June 30, 2003                           |   | —     |   | $          | 22.6       |   |
|                                                           |   |       |   |       |       |
| **Accumulated other  comprehensive loss:**                     |   |       |   |       |       |
| Beginning balance at December 31, 2002                    |   | —     |   | (16.3      | )          |
| Unrealized loss on derivative financial  instruments           |   | —     |   | (63.6      | )          |
| Change from current period hedge  transactions ineffectiveness |   | —     |   | 0.5        |       |
| Ending balance at June 30, 2003                           |   | —     |   | $          | (79.4      | ) |
|                                                           |   |       |   |       |       |
| **Total Partners’  Capital at June 30, 2003**        |   |       |   | $          | 1,078.3    |   |

 

The accompanying notes to theConsolidated Financial Statements are an integral part of this statement.

 

6

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***NOTES TO THECONSOLIDATED FINANCIAL STATEMENTS (unaudited)***

 

*1.*              **Basis ofPresentation**

* *

*The accompanying unaudited interim consolidatedfinancial statements have been prepared in accordance with accountingprinciples generally accepted in the United States of America for interimconsolidated financial information and with the instructions to Form 10-Q andRule 10-01 of Regulation S-X. Accordingly, they do not include all the information and footnotesrequired by accounting principles generally accepted in the United States ofAmerica for complete consolidated financial statements. In the opinion ofmanagement, they contain all adjustments, consisting only of normal recurringadjustments, which management considers necessary to present fairly thefinancial position as at June 30, 2003 and December 31, 2002; theresults of operations for the three and six month periods ended June 30,2003 and 2002; and cash flows for the six month periods ended June 30,2003 and 2002.  The results ofoperations for the three and six month periods ended June 30, 2003 shouldnot be taken as indicative of the results to be expected for the full year, dueto seasonality of portions of the natural gas business and maintenanceactivities.  The interim consolidatedfinancial statements should be read in conjunction with Enbridge EnergyPartners, L.P.’s (the “Partnership”) consolidated financial statements andnotes thereto presented in the Partnership’s Annual Report on Form 10-K for thefiscal year ended December 31, 2002.*

* *

*2.*              **NetIncome per Unit**

* *

Net income per unit is computed by dividingnet income, after deduction of Enbridge Energy Company, Inc.’s (the “GeneralPartner”) allocation, by the weighted average number of Class A and Class BCommon Units and i-units outstanding. The General Partner’s allocation is equal to an amount based upon itsgeneral partner interest, adjusted to reflect an amount equal to incentivedistributions and an amount required to reflect depreciation on the GeneralPartner’s historical cost basis for assets contributed on formation of thePartnership.  Net income per unit wasdetermined as follows:

 
|                                                                  |   | **Three  months ended  June 30,** | ** ** | **Six months  ended  June 30,** | ** ** |
|-----------------------------------------------------------------------|--------|----------------------------------------|------------|--------------------------------------|------------|
| **(in millions; except per unit  amounts)**                           |   | **2003**                               | ** ** | **2002**                             | ** ** | **2003** | ** ** | **2002** | ** ** |
| Net  income                                                           |   | $                                      | 23.3       |                                 | $          | 16.8 |   | $ | 55.9 |   | $ | 34.5 |   |
|                                                                  |   |                                   |       |                                 |       |   |   |   |   |
| Net  income allocated to General Partner                              |   | (0.4                                   | )          | (0.2                                 | )          | (1.1 | ) | (0.4 | ) |
| Incentive  distributions and historical cost depreciation adjustments |   | (4.3                                   | )          | (2.8                                 | )          | (8.5 | ) | (5.8 | ) |
|                                                                  |   | (4.7                                   | )          | (3.0                                 | )          | (9.6 | ) | (6.2 | ) |
|                                                                  |   |                                   |       |                                 |       |   |   |   |   |
| Net  income allocable to Common Units and i-units                     |   | $                                      | 18.6       |                                 | $          | 13.8 |   | $ | 46.3 |   | $ | 28.3 |   |
|                                                                  |   |                                   |       |                                 |       |   |   |   |   |
| Weighted  average units outstanding                                   |   | 46.8                                   |       | 35.2                                 |       | 45.7 |   | 34.4 |   |
|                                                                  |   |                                   |       |                                 |       |   |   |   |   |
| Net  income per unit                                                  |   | $                                      | 0.39       |                                 | $          | 0.39 |   | $ | 1.01 |   | $ | 0.82 |   |

* *

*3.*              **Distributions**

* *

On July 23,2003, the Partnership’s Board of Directors declared a distribution payable onAugust 14, 2003, to unitholders of record as of July 31, 2003, of its availablecash of $50.3 million or $0.925 per common unit, including $8.9 millionrelating to the i-units that will be retained by the Partnership for use in itsbusiness.

 

On April 24,2003, the Partnership’s Board of Directors declared a distribution payable onMay 15, 2003, to unitholders of record as of April 30, 2003, of itsavailable cash of $46.1 million or $0.925 per common unit, including $8.7million relating to the i-units that was retained by the Partnership for itsuse in its business.

 

OnJanuary 23, 2003, the Partnership’s Board of Directors declared adistribution payable on February 14, 2003, to unitholders of record as ofJanuary 31, 2003, of its available cash of $45.9 million or $0.925 percommon unit, including $8.5 million relating to the i-units that was retainedby the Partnership for its use in its business.

 

7

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*4.*              **EquityUnit Issuance**

* *

*On May 12, 2003, the Partnershipissued 3.35 million Class A Common Units at $44.79 per unit, which generatedproceeds, net of underwriters’ fees and discounts, commissions and issuanceexpenses, of approximately $143.4 million. Proceeds from this offering were used to reduce borrowings under thePartnership’s credit facility and an affiliate loan from Enbridge (U.S.)Inc.  On May 15, 2003, thePartnership issued an additional 502,500 Class A Common Units to theunderwriters pursuant to the exercise of the over-allotment option, resultingin additional proceeds to the Partnership, net of underwriters’ fees anddiscounts, commissions and issuance expenses, of approximately $21.3million.  In addition to the proceedsgenerated from the unit issuances, the General Partner contributed $3.5 millionto the Partnership to maintain its 2% general partner interest in thePartnership.*

* *

*5.*              **Debt**

* *

On May 27, 2003, the Partnership issued$200.0 million in aggregate principal amount of its 4.75% Notes due 2013 and$200.0 million in aggregate principal amount of its 5.95% Notes due 2033 (the“Notes”) in a private placement.  ThePartnership used the proceeds of approximately $396.3 million, net of expensesof approximately $3.0 million, to repay loans from affiliates of thePartnership and other bank debt.  ThePartnership recorded a discount of $0.7 million in connection with the issuanceof the Notes.  On June 30, 2003,the Partnership filed a Form S-4 with the Securities and Exchange Commission(the “SEC”) to register the exchange of the unregistered Notes for publiclyregistered Notes.

 

On January 24, 2003, the Partnershipamended and restated the terms of its two unsecured revolving creditfacilities.  The new facilities consistof the amended and restated $300.0 million three-year facility, which maturesin 2006, subject to extension as provided in the facilities, and the amendedand restated $300.0 million 364-day facility, which matures in 2004, subject toa one-year term out option and extension as provided in the facility.  The Partnership is the sole borrower underthe new facilities and there are no guarantees of the obligations under eitherfacility.  The amended and restatedterms of the facilities are substantially similar to the original facilitieswith the exception of certain amendments to the covenants.  Among other changes under the newfacilities, the Partnership must maintain a minimum interest coverage ratio of2.75 to 1.00 as of the end of each fiscal quarter and a maximum leverage ratioof 4.75 to 1.00 as defined in the amended and restated terms of thefacilities.  The Partnership is nolonger required to maintain a particular credit rating.  Although subsidiaries may incur debt subjectto certain restrictions and limitations under the new facilities, thePartnership expects to provide funding to its subsidiaries.  As of June 30, 2003, $80.0 million and$200.0 million were outstanding under the 364-day and three-year facilities,respectively.

 

*6.*              **DerivativeInstruments and Hedging Activities**

* *

*In May 2003 prior to the issuance of theNotes, the Partnership entered into 10 year and 30 year treasury lockagreements (the “agreements”) to hedge the fluctuations in the U.S. Treasurybond interest rates between the execution date of the swaps and the issuancedate of the fixed rate debt.  Theagreements were designated as cash flow hedges of future interest expense.  Upon issuance of the Notes, the agreementswere terminated and their aggregate mark to market value of $6.1 million waspaid and recorded in accumulated other comprehensive income and is beingamortized to interest expense over the term of the Notes.*

* *

*In May 2003, the Partnership entered into atreasury lock contract, maturing on October 1, 2003, for the purpose oflocking in the U.S. Treasury bond interest rate on anticipated debtofferings.  As of June 30, 2003,the lock totaled $0.3 million and is deemed fully effective.  All changes to the market value of thederivative instrument have been recorded in accumulated other comprehensiveincome.*

* *

*The changes in the market value of natural gashedging instruments that are attributable to hedge ineffectiveness, measured ona quarterly basis, are included in cost of natural gas expense in the period inwhich they occur.  During the second quarter2003, the Partnership recorded $0.5 million in cost of natural gas expense toreflect the ineffective portion of certain hedge transactions.*

* *

*8*

----

* *

*7.*              **Depreciation**

 

Based on athird-party study commissioned by management, revised depreciation rates forthe Lakehead System were implemented effective January 1, 2003, which representthe expected remaining service life of the pipeline system.  The third-party study will be filed with theFederal Energy Regulatory Commission (“FERC”) to conform regulatory andfinancial accounting depreciation rates of the Lakehead System.  Depreciation expense for the six monthsended June 30, 2003 was $46.2 million. Depreciation expense was $6.1 million lower than it would have been hadthe Partnership used previous depreciation rates, which was offset by $3.0million additional depreciation incurred on facilities placed into serviceduring the fourth quarter 2002.  Theannual composite rate changed from 3.9% to 3.22%.

* *

*8.*              **Segment Information**

* *

The Partnership’s business is divided into operating segments, definedas components of the enterprise about which financial information is availableand evaluated regularly by the Partnership in deciding how to allocateresources to an individual segment and in assessing performance of the segment.

 

The Partnership’s reportable segments are based on the types ofbusiness activity and management control. Each segment is managed separatelybecause each business requires different operating strategies.  The Partnership has five reportable businesssegments: Liquids Transportation, Gathering and Processing, Natural GasTransportation, Marketing and Corporate.

 

Due to the purchase of natural gas assets in October 2002, thePartnership changed the organization of its business segments effective in thefourth quarter of 2002.  Prior to thefourth quarter of 2002, the Partnership reported Transportation as one segment,which consisted of receipt and delivery of crude oil, liquid hydrocarbons,natural gas and natural gas liquids. These activities are now reported within 3 segments – LiquidsTransportation, Natural Gas Transportation and Gathering and Processing.  Prior period segment results have beenrestated to conform to the Partnership’s current organization.

 

The followingtables present certain financial information relating to the Partnership’sbusiness segments.

 
|                                           |   | **As of and  for the Three Months Ended June 30, 2003** |    |
|------------------------------------------------|--------|---------------------------------------------------------|---------|
|                                           |   | **Liquids  Transportation**                             |    | **Gathering  and  Processing** |   | **Natural  Gas  Transportation** |   | **Marketing** |   | **Corporate** |   | **Total** |   |
| Operating revenues                             |   | $                                                       | 81.8    |   | $ | 441.7 |   | $ | 35.0 |   | $ | 196.8 |   | $ | — |   | $ | 755.3 |   |
| Cost of natural gas                            |   | —                                                  |    | 405.6 |   | 23.3 |   | 194.5 |   | — |   | 623.4 |   |
| Operating and administrative                   |   | 26.9                                                    |    | 19.1 |   | 5.3 |   | 0.4 |   | 0.6 |   | 52.3 |   |
| Power                                          |   | 13.0                                                    |    | — |   | — |   | — |   | — |   | 13.0 |   |
| Depreciation and amortization                  |   | 14.5                                                    |    | 5.5 |   | 3.4 |   | 0.1 |   | — |   | 23.5 |   |
| Operating income                               |   | 27.4                                                    |    | 11.5 |   | 3.0 |   | 1.8 |   | (0.6 | ) | 43.1 |   |
| Interest and other income                      |   | —                                                  |    | — |   | — |   | — |   | 1.8 |   | 1.8 |   |
| Interest expense                               |   | —                                                  |    | — |   | — |   | — |   | (21.6 | ) | (21.6 | ) |
| Net income                                     |   | $                                                       | 27.4    |   | $ | 11.5 |   | $ | 3.0 |   | $ | 1.8 |   | $ | (20.4 | ) | $ | 23.3 |   |
|                                           |   |                                                    |    |   |   |   |   |   |   |   |   |   |   |
| Total assets                                   |   | $                                                       | 1,498.5 |   | $ | 746.5 |   | $ | 417.8 |   | $ | 225.0 |   | $ | 54.6 |   | $ | 2,942.4 |   |
| Goodwill                                       |   | $                                                       | —  |   | $ | 146.1 |   | $ | 72.9 |   | $ | 20.3 |   | $ | — |   | $ | 239.3 |   |
| Capital expenditures (excluding  acquisitions) |   | $                                                       | 15.1    |   | $ | 10.1 |   | $ | 1.1 |   | $ | 0.1 |   | $ | 0.9 |   | $ | 27.3 |   |

 

9

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|                                           |   | **As of and for the Three Months Ended June 30, 2002** |    |
|------------------------------------------------|--------|--------------------------------------------------------|---------|
|                                           |   | **Liquids  Transportation**                            |    | **Gathering and  Processing** |   | **Natural Gas  Transportation** |   | **Marketing** |   | **Corporate** |   | **Total** |   |
| Operating revenues                             |   | $                                                      | 81.0    |   | $ | 142.1 |   | $ | — |   | $ | — |   | $ | — |   | $ | 223.1 |   |
| Cost of natural gas                            |   | —                                                 |    | 130.8 |   | — |   | — |   | — |   | 130.8 |   |
| Operating and administrative                   |   | 24.1                                                   |    | 5.6 |   | — |   | — |   | 1.2 |   | 30.9 |   |
| Power                                          |   | 12.4                                                   |    | — |   | — |   | — |   |   |   | 12.4 |   |
| Depreciation and amortization                  |   | 16.1                                                   |    | 2.5 |   | — |   | — |   | — |   | 18.6 |   |
| Operating income                               |   | 28.4                                                   |    | 3.2 |   | — |   | — |   | (1.2 | ) | 30.4 |   |
| Interest and other income                      |   | —                                                 |    | — |   | — |   | — |   | 0.1 |   | 0.1 |   |
| Interest expense                               |   | —                                                 |    | — |   | — |   | — |   | (13.5 | ) | (13.5 | ) |
| Minority interest                              |   | —                                                 |    | — |   | — |   | — |   | (0.2 | ) | (0.2 | ) |
| Net income                                     |   | $                                                      | 28.4    |   | $ | 3.2 |   | $ | — |   | $ | — |   | $ | (14.8 | ) | $ | 16.8 |   |
|                                           |   |                                                   |    |   |   |   |   |   |   |   |   |   |   |
| Total assets                                   |   | $                                                      | 1,451.9 |   | $ | 286.5 |   | $ | — |   | $ | — |   | $ | 2.2 |   | $ | 1,740.6 |   |
| Goodwill                                       |   | $                                                      | —  |   | $ | 15.0 |   | $ | — |   | $ | — |   | $ | — |   | $ | 15.0 |   |
| Capital expenditures (excluding  acquisitions) |   | $                                                      | 70.2    |   | $ | 2.4 |   | $ | — |   | $ | — |   | $ | — |   | $ | 72.6 |   |

 
|                                           |   | **As of and  for the Six Months Ended June 30, 2003** | ** ** |
|------------------------------------------------|--------|-------------------------------------------------------|------------|
|                                           |   | **Liquids  Transportation**                           |       | **Gathering  and  Processing** | ** ** | **Natural  Gas  Transportation** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| Operating revenues                             |   | $                                                     | 167.2      |   | $ | 944.0 |   | $ | 64.5 |   | $ | 475.7 |   | $ | — |   | $ | 1,651.4 |   |
| Cost of natural gas                            |   | —                                                |       | 870.6 |   | 38.7 |   | 467.6 |   | — |   | 1,376.9 |   |
| Operating and administrative                   |   | 53.3                                                  |       | 38.1 |   | 11.0 |   | 0.8 |   | 1.7 |   | 104.9 |   |
| Power                                          |   | 25.7                                                  |       | — |   | — |   | — |   | — |   | 25.7 |   |
| Depreciation and amortization                  |   | 28.9                                                  |       | 11.1 |   | 6.8 |   | 0.1 |   | — |   | 46.9 |   |
| Operating income                               |   | 59.3                                                  |       | 24.2 |   | 8.0 |   | 7.2 |   | (1.7 | ) | 97.0 |   |
| Interest and other income                      |   | —                                                |       | — |   | — |   | — |   | 1.8 |   | 1.8 |   |
| Interest expense                               |   | —                                                |       | — |   | — |   | — |   | (42.9 | ) | (42.9 | ) |
| Net income                                     |   | $                                                     | 59.3       |   | $ | 24.2 |   | $ | 8.0 |   | $ | 7.2 |   | $ | (42.8 | ) | $ | 55.9 |   |
| Total assets                                   |   | $                                                     | 1,498.5    |   | $ | 746.5 |   | $ | 417.8 |   | $ | 225.0 |   | $ | 54.6 |   | $ | 2,942.4 |   |
| Goodwill                                       |   | $                                                     | —     |   | $ | 146.1 |   | $ | 72.9 |   | $ | 20.3 |   | $ | — |   | $ | 239.3 |   |
| Capital expenditures (excluding  acquisitions) |   | $                                                     | 20.0       |   | $ | 21.3 |   | $ | 2.4 |   | $ | 0.1 |   | $ | 1.8 |   | $ | 45.6 |   |

 
|                                           |   | **As of and for the Six Months Ended June 30, 2002** | ** ** |
|------------------------------------------------|--------|------------------------------------------------------|------------|
|                                           |   | **Liquids  Transportation**                          |       | **Gathering  and  Processing** | ** ** | **Natural  Gas  Transportation** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| Operating revenues                             |   | $                                                    | 163.6      |   | $ | 241.3 |   | $ | — |   | $ | — |   | $ | — |   | $ | 404.9 |   |
| Cost of natural gas                            |   | —                                               |       | 220.4 |   | — |   | — |   | — |   | 220.4 |   |
| Operating and administrative                   |   | 46.7                                                 |       | 10.6 |   | — |   | — |   | 1.4 |   | 58.7 |   |
| Power                                          |   | 26.0                                                 |       | — |   | — |   | — |   | — |   | 26.0 |   |
| Depreciation and amortization                  |   | 32.0                                                 |       | 4.9 |   | — |   | — |   | — |   | 36.9 |   |
| Operating income                               |   | 58.9                                                 |       | 5.4 |   | — |   | — |   | (1.4 | ) | 62.9 |   |
| Interest and other income                      |   | —                                               |       | — |   | — |   | — |   | 0.2 |   | 0.2 |   |
| Interest expense                               |   | —                                               |       | — |   | — |   | — |   | (28.2 | ) | (28.2 | ) |
| Minority interest                              |   | —                                               |       | — |   | — |   | — |   | (0.4 | ) | (0.4 | ) |
| Net income                                     |   | $                                                    | 58.9       |   | $ | 5.4 |   | $ | — |   | $ | — |   | $ | (29.8 | ) | $ | 34.5 |   |
| Total assets                                   |   | $                                                    | 1,451.9    |   | $ | 286.5 |   | $ | — |   | $ | — |   | $ | 2.2 |   | $ | 1,740.6 |   |
| Goodwill                                       |   | $                                                    | —     |   | $ | 15.0 |   | $ | — |   | $ | — |   | $ | — |   | $ | 15.0 |   |
| Capital expenditures (excluding  acquisitions) |   | $                                                    | 96.8       |   | $ | 5.8 |   | $ | — |   | $ | — |   | $ | — |   | $ | 102.6 |   |

 

10

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*9.**             ***Comparative Amounts**

* *

Certainreclassifications have been made to the prior period’s reported amounts toconform to the classifications used in the 2003 consolidated financialstatements.  These reclassificationshave no impact on net income.

 

*10.***   New Accounting Pronouncements**

** **

In June 2001,the FASB issued SFAS No. 143,  *Accounting for Asset Retirement Obligations*,which must be adopted in years beginning after June 15, 2002.  This standard requires legal obligationsassociated with the retirement of long-lived tangible assets to be recognizedat fair value.  When the liability isinitially recorded, the cost is capitalized by increasing the assets carryingvalue, which is subsequently depreciated over its useful life.  The new standard was adopted January 1, 2003and did not have a material impact on the Partnership's financial position,results of operations, or cash flows.

 

*11.***   Subsequent Event**

 

In 1998, when the Kansas Pipeline system (“KPC”) becamesubject to the FERC jurisdiction, the FERC established initial rates based uponan annual cost of service of approximately $31 million.  Since that time, these initial rates havebeen the subject of various ongoing challenges that remain unresolved.

 

The United States Court ofAppeals, for the D.C. Circuit, issued an order on August 12, 2003, vacating theFERC’s 2001 Remand Order and 2002 Rehearing Order and remanded the issue ofKPC’s initial rates back to the FERC with directions that the FERC address the question of an appropriate raterefund.  In prior KPC Orders in thisproceeding, the FERC determined that it had no authority to impose a refundcondition on initial rates.  ThePartnership is currently considering its options, including filing forrehearing of the Court’s August 12, 2003 Order.  There are other actions and administrative proceedings that maybe undertaken in connection with the Court’s determination.  The outcome of any proceedings, includingthe amount of any refunds that may be ordered, is uncertain.   If the FERC determines refunds arerequired, after all administrative options and court appeals are exhausted, theamount of the refunds may be material to the earnings of the Partnership.

 

 

***ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTSOF OPERATIONS***

 

**Resultsof Operations - Overview**

 

Net income for the secondquarter of 2003 improved 39% to $23.3 million compared with $16.8 million forthe second quarter of 2002.  Net incomefor the six months ended June 30, 2003 improved 62% to $55.9 million comparedwith $34.5 million for the six months ended June 30, 2002.  The increase in net income in both periodsin 2003 was primarily due to the inclusion of the Midcoast System results.  The comparable numbers for 2002 did notinclude earnings from the Midcoast System, as these assets were purchased inthe fourth quarter of 2002.

 

Earningsper unit for the second quarter of 2003 was $0.39 per unit, unchanged from thesecond quarter of 2002.  Earnings perunit for the six months ended June 30, 2003 was $1.01 per unit compared with$0.82 per unit for the six months ended June 30, 2002.  Earnings per unit was higher for the sixmonths ended June 30, 2003 due to an increase in net income primarily due tothe Midcoast acquisition, partially offset by an increase in the number ofunits outstanding.  Due to the i-unitissuance in October 2002 and a Class A common unit issuance in May 2003, theweighted average number of common units outstanding increased.  On a quarterly basis, the weighted averagenumber of common units outstanding increased from 35.2 million in the secondquarter of 2002 to 46.8 million in the second quarter of 2003.  On a half year basis, it increased from 34.4million in the first six months of 2002 to 45.7 million in the first six monthsof 2003.

 

The following table reflectsoperating income by business segment and corporate charges for each of thethree and six-month periods ended June 30, 2003 and 2002.

 

|                                    |   | **Three months ended  June 30,** |   | **Six months ended  June 30,** |   |
|-----------------------------------------|--------|----------------------------------|--------|--------------------------------|--------|
| **(unaudited; dollars in millions)**    |   | **2003**                         |   | **2002**                       |   | **2003** |   | **2002** |   |
|                                    |   |                             |   |                           |   |   |   |   | ** ** |
|                                    |   |                             |   |                           |   |   |   |   |   |
| **Operating Income**                    |   |                             |   |                           |   |   |   |   |   |
| Liquids Transportation                  |   | $                                | 27.4   |                           | $      | 28.4 |   | $ | 59.3 |   | $ | 58.9 |   |
| Gathering and Processing                |   | 11.5                             |   | 3.2                            |   | 24.2 |   | 5.4 |   |
| Natural Gas Transportation              |   | 3.0                              |   | —                         |   | 8.0 |   | — |   |
| Marketing                               |   | 1.8                              |   | —                         |   | 7.2 |   | — |   |
| Corporate, operating and administrative |   | (0.6                             | )      | (1.2                           | )      | (1.7 | ) | (1.4 | ) |
| **Total Operating Income**              |   | $                                | 43.1   |                           | $      | 30.4 |   | $ | 97.0 |   | $ | 62.9 |   |
| Other income (expense), net             |   | (19.8                            | )      | (13.6                          | )      | (41.1 | ) | (28.4 | ) |
| **Net Income**                          |   | $                                | 23.3   |                           | $      | 16.8 |   | $ | 55.9 |   | $ | 34.5 |   |

 

**Resultsof Operations – by Segment**

 

***Liquids Transportation***

 

***Three months endedJune 30, 2003 compared with three months ended June 30, 2002***

 

*Operating income. *Operating income decreased for the threemonths ended June 30, 2003 by approximately $1.0 million to $27.4 million ascompared with $28.4 million for the three months ended June 30, 2002.  Operating income was lower in 2003 primarilydue to slightly higher operating and administrative expenses primarily relatedto costs associated with pipeline leaks on the Lakehead system that occurredsubsequent to June 30, 2002.

 

11

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*Operating revenue. *Operating revenue for the second quarterof 2003 was $81.8 million compared with $81.0 million in 2002.  Operating revenue was higher in 2003compared to 2002, as slightly lower deliveries on the Lakehead system were morethan offset by higher tariffs.  Tariffswere higher due to the positive Federal Energy Regulatory Commission (“FERC”)indexed-tariff adjustment effective July 1, 2002, and an increase in the SEP IItariff effective May 1, 2003.  As well,the amount of heavy oil transported on the Lakehead System, which attracts ahigher tariff, was higher in 2003 compared to 2002.

 

*Deliveries. *Deliverieson the Lakehead System averaged 1.294 million barrels per day (“bpd”) for the secondquarter of 2003 compared with 1.310 million bpd in the second quarter of2002.  Deliveries were lower thanexpected due to customer start-up problems at the new Alberta oil sandsprojects, as well as the continuing maintenance problems at two of the existingoil sands operations in northern Alberta. Contingent upon these crude oil supply problems lessening, the Partnership anticipates that deliveries willimprove over the second half of 2003 to average between 1.34 and 1.40 millionbpd on a full-year basis.  Deliveries onthe North Dakota System averaged approximately 64.5 thousand bpd on thetrunkline and approximately 8.2 thousand bpd on the gathering system for thesecond quarter of 2003.  This compareswith approximately 56.2 thousand bpd on the trunkline and approximately 8.7thousand bpd on the gathering system for the second quarter of 2002.

 

*Operating and administrative expenses. *Operating and administrative expenses were $26.9million for the second quarter of 2003 compared with $24.1 million in thesecond quarter of 2002.  Operating andadministrative expenses were higher in 2003, primarily due to costs related torecent leaks on the Lakehead system of approximately $1.0 million and higherpost-retirement benefits and pension costs.

 

*Depreciation expense. *Depreciation expense was $14.5 million for thesecond quarter of 2003 compared with $16.1 million in the second quarter of2002.  The decrease was primarilydue to revised depreciation rates, offset by an increase in depreciationexpense associated with additional facilities placed into service during thefourth quarter 2002.  The reviseddepreciation rates on the Lakehead System will be filed with FERC to beeffective on January 1, 2003, to better represent the expected remainingservice life of the pipeline system. Depreciation expense for the three months ended June 30, 2003, was $3.0million lower than it would have been using previous depreciation rates.

 

***Six months endedJune 30, 2003 compared with six months ended June 30, 2002***

 

*Operating income. *Operating income increased for the sixmonths ended June 30, 2003 by approximately $0.4 million to $59.3 million ascompared with $58.9 million for the six months ended June 30, 2002.  Operating income was higher in 2003primarily due to higher revenues and lower depreciation, partially offset byhigher operating expenses.

 

*Operating revenue. *Operating revenue for the first sixmonths of 2003 was $167.2 million compared with $163.6 million in 2002 for thesame reasons as noted above in the three-month analysis.

 

*Deliveries. *Deliverieson the Lakehead System averaged 1.310 million bpd for the six months ended June30, 2003 compared with 1.312 million bpd in 2002.  For the six-month period ending June 30, 2003, deliveries werelower than last year for the same reasons as noted above in the three-monthanalysis.  Deliveries on the North Dakota System averaged approximately 68.5thousand bpd on the trunkline and approximately 7.9 thousand bpd on thegathering system for the period ended June 30, 2003.  This compares with approximately 56.8 thousand bpd on thetrunkline and approximately 8.6 thousand bpd on the gathering system for thesame period in 2002.

 

*Operating and administrative expenses. *Operating and administrative expenses were $53.3million for the six months ended June 30, 2003, compared with $46.7 million inthe second quarter of 2002.  Operatingand administrative expenses were higher in 2003 compared to 2002 primarily dueto costs associated with the cleanup and remediation of recent leaks on theLakehead System of $4.7 million (net of expected insurance recoveries of $1.7million) and higher post-retirement benefits and pension costs.

 

*Depreciationexpense. *Depreciation expense was $28.9 million for thesix months ended June 30, 2003 compared with $32.0 million in 2002.  The decrease of $3.1 million was dueto revised depreciation rates on the Lakehead system, offset by additionaldepreciation expense incurred on facilities placed into service during thefourth quarter 2002.    Depreciationexpense for the six months ended June 30, 2003, was $6.1 million lower than itwould have been using previous depreciation rates.

 

12

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***Gathering andProcessing***

 

The East Texas System wasacquired on November 30, 2001, and additional gathering and processing systemswere purchased as part of the Midcoast System acquisition on October 17, 2002.Therefore, comparative results for 2002 include only the results of operationsfrom the East Texas System.

 

*Volumes. *The following table indicates the average dailyvolume for each of the major systems in the Partnership’s Gathering andProcessing segment during the three and six months ended June 30, 2003 and2002, in million British thermal units per day (“Mmbtu/d”).

 

|                   |   | **Three months ended  June 30,** |       | **Six months ended  June 30,** |       |
|------------------------|--------|----------------------------------|------------|--------------------------------|------------|
|                   |   | **2003**                         |       | **2002**                       |       | **2003** |   | **2002** |   |
| **Gathering Systems:** |   |                             | ** ** |                           | ** ** |   | ** ** |   | ** ** |
| East Texas             |   | 445                              |       | 383                            |       | 436 |   | 390 |   |
| Anadarko               |   | 249                              |       | N/A                            |       | 242 |   | N/A |   |
| Northeast Texas        |   | 135                              |       | N/A                            |       | 135 |   | N/A |   |
| Tilden                 |   | 37                               |       | N/A                            |       | 36 |   | N/A |   |
| Total                  |   | 866                              |       | 383                            |       | 849 |   | 390 |   |

 

*East Texas System. *Operatingincome for the second quarter of 2003 of $2.9 million was slightly lower by$0.3 million compared with the same period in 2002. Higher volumes were offsetby lower processing margins due to higher gas prices during 2003. Operatingincome for the East Texas System was $6.8 million for the six months ended 2003compared with $5.4 million for the same period ended June 30, 2002.  The increase of $1.4 million was primarilydue to higher volumes and the absence of expenses related to a treating plantmaintenance shutdown that occurred during the first half of 2002.  Volume on the East Texas System increasedfrom 390 Mmbtu/d during the six months ended June 30, 2002 to 436 Mmbtu/dduring the six months ended June 30, 2003. This increase in volume is due to higher natural gas production and newdrilling by producers in the East Texas area.

 

*Other Gathering and Processing systems. *Operating incomerelated to processing on the Anadarko system was negatively impacted by highnatural gas prices during the second quarter of 2003.  Volumes on the Northeast Texas system continued to be stableduring the second quarter of 2003 due to recent supply additions.  Expectations are for stable supply on theNortheast Texas system during the last half of 2003.

 

Volatility in natural gas prices can impact the operating income of theGathering and Processing segment.  Whennatural gas prices are high, processing activities may be non-economic oncertain facilities where processing is mandatory as a result of downstreampipeline quality specifications.  Totalprocessing margin is expected to account for approximately 15% of the totaloperating income for this segment during the full year of 2003. The remainingoperating income associated with this segment is derived from fixed fee,percentage-of-index contract structures, and trucking operations.

 

During the first six months of 2003, historically high natural gasprices made keep-whole processing contracts non-economic for the gathering andprocessing segment and resulted in a negative processing margin ofapproximately $2.0 million.  First ofthe month natural gas prices fluctuated between $4.96 and $9.11 per Mmbtu resultingin an average price of approximately $6 per Mmbtu during the six months endedJune 30, 2003.  Due to fluctuations inboth the natural gas and natural gas liquids prices, the processing margin waspositive in some months and negative in others.  When processing margins were positive, the Partnership processedvolumes beyond the contractual mandatory****levels.  Assuming an approximate $5 per Mmbtu naturalgas price and stable NGL prices, it is expected that processing margins in theGathering and Processing segment will break even for the remainder of the year.Should natural gas prices increase by $1 per Mmbtu and remain constant for theentire second half of 2003, processing margins could be****negative approximately $4.0 million forthe last six months of 2003.  Thisestimate assumes constant NGL prices, expected natural gas volumes, and otherassumptions.  Natural gas price changeswill also impact contractual in-kind natural gas operational balancingagreements, which are revalued monthly at market prices.

 

***Natural Gas Transportation***

 

The Natural Gas Transportation segment was established upon theacquisition of the Midcoast System on October 17, 2002.  This segment’s results of operations areincluded in the Partnership’s results since that date and, therefore, there isno comparative data for prior periods.

 

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Natural Gas Transportation systems contributed $3.0million to operating income for the three months and $8.0 million for the sixmonths ended June 30, 2003.  Performanceof the Natural Gas Transportation segment is largely dependent upon revenuesderived from reserved pipeline capacity. Natural gas transportation revenue is typically higher in the wintermonths from increased rates and pipeline reserve capacities, thus the first andfourth quarter operating income is typically higher as compared to the secondand third quarter operating income.

 

The table below indicates the average daily volumes in Mmbtu/d for themajor systems in the Partnership’s Natural Gas Transportation segment for thethree and six-month periods ended June 30, 2003.

 

|                                           |   | **Three months ended  June 30, 2003** |   | **Six months ended  June 30, 2003** |   |
|------------------------------------------------|--------|---------------------------------------|--------|-------------------------------------|--------|
|                                           |   | **(average  Mmbtu/d)**                |   |
| **Major Natural Gas  Transportation Systems:** |   |                                  |   |                                |   |
| UTOS  Pipeline                                 |   | 234                                   |   | 241                                 |   |
| MidLa Pipeline                                 |   | 123                                   |   | 121                                 |   |
| AlaTenn Pipeline                               |   | 50                                    |   | 66                                  |   |
| Kansas Pipeline                                |   | 42                                    |   | 59                                  |   |
| Bamagas Pipeline                               |   | 17                                    |   | 14                                  |   |
| **Other Major Intrastates**                    |   | 180                                   |   | 182                                 |   |
| Total                                          |   | 646                                   |   | 683                                 |   |

 

***Marketing***

 

TheMarketing segment was established upon the acquisition of the Midcoast Systemon October 17, 2002. This segment’s results of operations are included in thePartnership’s results since that date, and therefore, there is no comparativedata for prior periods.

 

Operatingincome for the Marketing segment was $1.8 million for the three months and $7.2million for the six months ended June 30, 2003.  Colder weather during the first four months of 2003 createdgreater demand for natural gas.  Thisincreased the ability to optimize firm transportation contracts in competitivemarkets, because of strong demand from wholesale customers.  Results for the Marketing segment for thesix months ended June 30, 2003, also include the positive impact of gains ofapproximately $1.9 million due to the settlement of disputed amounts.  Typically, the first and fourth quarters willresult in higher operating income for the Marketing segment due to colderweather in the market areas served by this segment because colder weathergenerates significant incremental sales to the Partnership’s wholesalecustomers and creates the opportunity to optimize transportation and storageagreements.

 

***Corporate***

 

Interestand other income (expense) was $1.8 million for both the three and six-monthperiods ending June 30, 2003, compared with $0.1 million for the three monthsand $0.2 million for the six months ended June 30, 2002.  The balance for 2003 is largely explained bynon-recurring gains related to settlements of previously disputed amountsassociated with certain assets purchased in the Midcoast acquisition in October2002.

 

Interestexpense was $21.6 million for the three months ended June 30, 2003, comparedwith $13.5 million for the same period in 2002.  Interest expense was $42.9 million for the six months ended June30, 2003, compared with $28.2 million for the same period in 2002.  The increase in both periods is due tohigher debt balances in 2003 compared to 2002, partially offset by lowerinterest rates.

 

**Liquidity and CapitalResources**

 

The Partnership believes that it will continue to have adequateliquidity to fund future recurring operating and investing activities.  The primary cash requirements for thePartnership consist of normal operating expenses, maintenance and expansioncapital expenditures, debt service payments, distributions to partners andacquisitions of new businesses. Short-term

 

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cash requirements, such as operating expenses, maintenance capitalexpenditures and quarterly distributions to partners, are expected to be fundedby operating cash flows.  Long-term cashrequirements for expansion projects and acquisitions are expected to be fundedby several sources, including cash flows from operating activities, borrowingsunder credit facilities, and the issuance of additional equity and debtsecurities, including common units and i-units.  The Partnership’s ability to complete future debt and equityofferings and the timing of any such offerings will depend on various factors,including prevailing market conditions, interest rates and the financialcondition of the Partnership and its credit rating at the time.

 

Working capital decreased by $46.6 million to ($107.7) million at June30, 2003, compared with ($61.1) million at December 31, 2002, primarily due tothe net increase in current maturities and short-term debt. The increase ofcurrent maturities of long-term debt relates to the 364-Day Credit Facility,which is due in January 2004.  To theextent that an outstanding balance exists at maturity, the Partnershipanticipates refinancing through an extended or renegotiated credit facility.

 

At June 30, 2003, cash and cash equivalents totaled $74.2 million,compared with $60.3 million at December 31, 2002.  Of this $74.2 million, $50.3 million ($0.925 per unit) will beused for the distribution payable August 14, 2003, including $8.9 millionrelating to the i-units, which will be retained by the Partnership for use inits business.  The remaining $23.9million is available for future cash distributions, capital expenditures orother business needs.

 

Cash flow from operatingactivities for the six months ended June 30, 2003 was $75.6 million comparedwith $81.0 million for the same period last year.  The decrease of $5.4 million is primarily due to changes inaccounts payable and accounts receivable, which was partially offset by anincrease in net income and accrued gas purchases.  The nature of the Partnership's operating activities aredifferent in the period ending June 30, 2003 compared with the same period in2002, due to the acquisition of the Midcoast natural gas assets in October2002. The price of natural gas can impact the variability of the accountspayable, accrued gas purchases and accounts receivable balances related to thePartnership’s natural gas business. Cash from operating activities for the six months ended June 30, 2003was also negatively impacted by a $6.1 million payment made upon termination ofderivative transactions related to an interest rate hedge that was put intoplace for the May 2003 debt issuance.

 

Cash flow used in investingactivities during the six months ended June 30, 2003 was $51.4 million,compared with $103.7 million for the same period in 2002.  The decrease of $52.3 million is primarilydue to a decrease in additions to property, plant and equipment associated withthe Terrace Phase III expansion during 2003 as compared to 2002.  The majority of the construction activityrelated to the Terrace Phase III expansion occurred during 2002.

 

Cash flow used in financingactivities during the six months ended June 30, 2003 was ($10.3) million,compared with cash flow provided by financing activities of $36.4 million forthe same period in 2002.  The decreasein cash flow is primarily due to the changes in debt, which include therepayments of loans from the general partner of $316.0 million and other debtrepayments of $184.0 million for credit facilities, as compared to additionalnet borrowings of $130.0 million in 2002. This was partially offset by the issuance of senior unsecured Notes of$396.3 million and Class A common unit issuances in May 2003 of $168.2 million,compared to only $93.2 million in Class A common unit issuances during thefirst six months of 2002.

 

On May 12, 2003, thePartnership issued 3.35 million Class A Common Units at $44.79 per unit, whichgenerated proceeds, net of underwriters’ fees and discounts, commissions andissuance expenses, of approximately $143.4 million.  Proceeds from this offering were used to reduce externalborrowings on the Partnership’s credit facility and an affiliate loan fromEnbridge (U.S.) Inc.  On May 15, 2003,the Partnership issued an additional 502,500 Class A Common Units to theunderwriters in the above offering upon exercise of their over-allotmentoption, resulting in additional proceeds to the Partnership, net ofunderwriters’ fees and discounts, commissions and issuance expenses, ofapproximately $21.3 million.  Inaddition to the proceeds generated from the unit issuances, the General Partnercontributed $3.5 million to the Partnership to maintain its 2% general partnerinterest in the Partnership*.*

 

On May 27, 2003, thePartnership issued $200.0 million in aggregate principal amount of its 4.75%Notes due 2013 and $200.0 million in aggregate principal amount of its 5.95%Notes due 2033 (the “Notes”) in a private placement.  The Partnership used the proceeds of approximately $396.3million, net of expenses of approximately $3.0 million, to repay existing loansfrom affiliates of Enbridge Inc. and other bank debt.  The Partnership recorded a discount of $0.7 million inconjunction with the issuance of the two series of Notes.  On June 30, 2003, the Partnership filed aForm S-4 with the Securities and Exchange Commission (the “SEC”) to registeroffers to exchange the unregistered Notes for publicly registered Notes.

 

On June 30, 2003, the Partnershipfiled a universal shelf registration statement with the SEC.  The Partnership may offer and sell debtsecurities or Class A Common Units, from time to time, up to a total of $1.5billion, with the amount, price and terms to be determined at the

 

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time of the sale.  The Partnership expects to use the netproceeds from any future sales of securities under the universal shelfregistration statement for operations and for other general corporate purposes,including repayment or refinancing of borrowings, working capital, capitalexpenditures, or acquisitions of businesses or assets.

 

In May 2003, Moody’s assignedthe Partnership’s senior unsecured debt a Baa2 rating.  In May 2003, Moody’s also lowered its seniorunsecured debt rating of Enbridge Energy, Limited Partnership’s, a wholly-ownedsubsidiary of the Partnership, from A3 to Baa1.

 

The Partnership anticipatesspending approximately $84 million for pipeline system enhancements, $27million for core maintenance and $51 million for Lakehead System expansionprojects in 2003.  Excluding majorexpansion projects, ongoing capital expenditures are expected to averageapproximately $60 million on an annual basis (approximately 45% for coremaintenance and 55% for enhancement of the systems).  Core maintenance activities, such as the replacement of equipmentand planned major maintenance programs, will be undertaken to enable thePartnership’s systems to continue to operate at their maximum operating capacity.  Enhancements to the systems, such as renewaland replacement of pipe, are expected to extend the life of the systems, reducecosts or enhance revenues, and permit the Partnership to respond to developingindustry and government standards and the changing service expectations of itscustomers. The Partnership continuously evaluates capital projects that mayimpact the estimates noted in this paragraph.

 

**GeneralMatters**

 

In 1998, when the Kansas Pipeline system (“KPC”) became subject to theFERC jurisdiction, the FERC established initial rates based upon an annual costof service of approximately $31 million. Since that time, these initial rates have been the subject of variousongoing challenges that remain unresolved. 

 

The United States Court of Appeals, for the D.C. Circuit, issued anorder on August 12, 2003, vacating the FERC’s 2001 Remand Order and 2002Rehearing Order and remanded the issue of KPC’s initial rates back to the FERCwith directions that the FERC address the question of an appropriate raterefund.  In prior KPC Orders in thisproceeding, the FERC determined that it had no authority to impose a refundcondition on initial rates.  ThePartnership is currently considering its options, including filing forrehearing of the Court’s August 12, 2003 Order.  There are other actions and administrative proceedings that maybe undertaken in connection with the Court’s determination.  The outcome of any proceedings, includingthe amount of any refunds that may be ordered, is uncertain.   If the FERC determines refunds arerequired, after all administrative options and court appeals are exhausted, theamount of the refunds may be material to the earnings of the Partnership.

 

UTOS Pipeline (“UTOS”) filed arate case pursuant to Section 4 of the Natural Gas Act (“NGA”) on March 31,2003 in FERC Docket No. RP03-335-000. The rates proposed by UTOS would result in an increase in revenue ofapproximately $1 million when compared to its currently effective rates.  On April 30, 2003, the FERC accepted andsuspended the proposed increase until the earlier of October 1, 2003 or on thedate the FERC specifies in any future order issued in this proceeding.  On May 30, 2003, UTOS filed an offersettlement, which would resolve all issues in this case and would result in thecontinued use of UTOS’ current rates for three years.  An order approving the proposed settlement was received on July23, 2003.

 

On June 25, 2003, the Partnership and Williams Field Services(“Williams”) mutually agreed to terminate an agreement for the sale by Williamsof certain South Texas natural gas transmission lines to the Partnership.  On May 2, 2003, the FERC issued an orderdenying the abandonment of the South Texas system, reversing a previous rulinggranting the approvals necessary for the sale. This decision effectively prevents the sale from proceeding under theterms of the purchase and sale agreement. The Partnership understands that Williams intends to pursue analternative transaction with the Partnership or other buyers under a structurethat is responsive to the FERC order.

 

Effective July 1, 2003, in compliance with the indexed rate ceilingsallowed by the FERC, the Partnership decreased its rates for transportation onthe Lakehead and North Dakota Systems by an average of approximately 1.3%.  The Partnership anticipates that thedecrease in tariff rates will not have a material impact on the Partnership’sfinancial condition and results of operations.

 

***ITEM 3.******                         QUANTITATIVEAND QUALITATIVE DISCLOSURE ABOUT MARKET RISK***

 

The Partnership’s financialinstrument market risk is impacted by changes in interest rates. ThePartnership’s exposure to movements in interest rates is managed through itslong-term debt ratio target, its allocation of fixed and floating rate debt andthe use of interest rate risk management agreements.  Information about the Partnership’s financial instruments, whichare sensitive to changes in interest rates, has not changed from that presentedin the Partnership’s 2002 Annual Report on Form 10-K. Approximately $280.0million of the Partnership’s total outstanding debt carries a floating interestrate.  Of the $280.0 million, $240.0million has been hedged with interest rate swaps effective through November 3,2003.

 

The Partnership’s earnings andcash flows associated with its Liquids Transportation systems are notsignificantly impacted by changes in commodity prices, as the Partnership doesnot own the crude oil and NGLs it transports. However, the Partnership has commodity risk related to degradation lossesassociated with the fluctuating differentials between the price

 

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of heavy crude oil relative tolight crude oil.  Commodity prices havea significant impact on the underlying supply of, and demand for, crude oil andNGLs that the Partnership transports.

 

The totalchange in value of the financial derivatives over the quarter was predominantlydriven by the significant rise in near and long term natural gas forwardprices.  As our natural gas hedge portfoliois largely comprised of long term fixed price forward sale agreements, anincrease in the forward market prices will cause the unrealized hedge loss toincrease.

 

Withthe Partnership’s acquisition of the East Texas System on November 30, 2001,and the natural gas assets in October 2002, a portion of the Partnership’searnings and cash flows are exposed to movements in the prices of natural gasand NGLs.  The Partnership has enteredinto hedge transactions to mitigate exposure to movements in these prices.  Pursuant to policies approved by the Boardof Directors of its General Partner, the Partnership may not enter intoderivative instruments for speculative purposes.  All financial derivative transactions must be undertaken withcreditworthy counterparties.

 

***ITEM 4.******                         CONTROLSAND PROCEDURES***

 

The Partnership and EnbridgeInc. maintain systems of disclosure controls and procedures designed to providereasonable assurance that the Partnership is able to record, process, summarizeand report the information required in the Partnership’s annual and quarterlyreports under the Securities Exchange Act of 1934.  Management of the Partnership has evaluated the effectiveness ofour disclosure controls and procedures within 90 days prior to the filingdate of this report.  Based upon thatevaluation, our principal executive officer and principal financial officerconcluded that our disclosure controls and procedures are effective toaccomplish their purpose.  In conductingthis assessment, management of the Partnership relied on similar evaluationsconducted by employees of Enbridge Inc. affiliates who provide certaintreasury, accounting and other services on behalf of the Partnership.  No significant changes were made to ourinternal controls or other factors that could significantly affect thesecontrols subsequent to the date of their evaluation, nor were any correctiveactions with respect to significant deficiencies and material weaknessesnecessary subsequent to that date.

 

***PART II - OTHER INFORMATION***

 

***ITEM 1. LEGAL PROCEEDINGS***

 

A settlementbecame final on July 7, 2003 with Kansas Gas Services (KGS), Kansas CorporationCommission and the Partnership; therefore the Partnership will invoice KGSretroactively for the settlement rates from November 1, 2002 in August2003.  The settlement is not expected tohave a material impact on the results of the Partnership.

 

The Partnership is aparticipant in other various legal proceedings arising in the ordinary courseof business.  Some of these proceedingsare covered, in whole or in part, by insurance.  The Partnership believes that the outcome of all theseproceedings will not, individually or in the aggregate, have a material adverseeffect on the financial condition of the Partnership.

 

Forinformation regarding other legal proceedings arising in 2002 or with regard towhich material developments were reported during 2002, see Part I. Item 3.,“Legal Proceedings,” in the Partnership’s Annual Report on Form 10-K for theyear ended December 31, 2002.

 

***ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K***

 

a)             Exhibits

 

31.1 Sarbanes-Oxley Section302(a) Certification of Principal Executive Officer.

31.2 Sarbanes-Oxley Section302(a) Certification of Principal Financial Officer.

32.1 Certification of PrincipalExecutive Officer.

32.2 Certification of PrincipalFinancial Officer.

 

 

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b)            Reports on Form 8-K

 

The Partnership filed thefollowing reports on Form 8-K during the second quarter of 2003:

 

A report on Form 8-K wasfiled on June 20, 2003 to provide additional historical financial informationrelated to Enbridge Midcoast Energy, Inc. and additional pro forma financialinformation related to the acquisition of Assets as described in thePartnership’s Form 8-K filed on October 31, 2002.

 

A report on Form 8-K wasfiled on May 29, 2003 attaching a press release dated May 20, 2003announcing a private offering of $200.0 million principal amount of 4.75% Notesdue 2013 and $200.0 principal amount of 5.95% Notes due 2033.

 

A report on Form 8-K wasfiled on May 8, 2003 announcing that on May 6, 2003 the Partnershipentered into an Underwriting Agreement relating to the offering of up to3,852,500 Class A Common Units representing limited partner interests inthe Partnership, including an over-allotment option to purchase 502,500 Class ACommon Units.

 

A report on Form 8-K wasfiled on May 5, 2003 that contains the Consolidated Statements ofFinancial Position of Enbridge Energy Company, Inc., at December 31,2002 and December 31, 2001.  EnbridgeEnergy Company, Inc., is the General Partner of the Partnership.

 

A report on Form 8-K wasfiled on May 5, 2003 to file a preliminary prospectus supplement andaccompanying prospectus for the offering of 2,750,000 Class A CommonUnits.  The prospectus supplement alsorelates to an option granted by the Partnership to the underwriters to purchasean additional 412,500 Class A Common Units to cover any over-allotments.

 

A report on Form 8-K was filedon April 24, 2003 attaching a press release dated April 24, 2003 regarding thefinancial results for the three months ended March 31, 2003.

 

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**SIGNATURE**

 

Pursuant to the requirements of the Securities Exchange Act of 1934,the Registrant has duly caused this report to be signed on its behalf by theundersigned thereunto duly authorized.

 

 
|   | **ENBRIDGE ENERGY PARTNERS, L.P.** |
|--------|------------------------------------|
|   |                               | (Registrant) |
|   |                               |
|   | By:                                | Enbridge  Energy Management, L.L.C. |
|   |                               | as delegate  of |
|   |                               | Enbridge  Energy Company, Inc. |
|   |                               | as General  Partner |
|   |                               |
|   |                               |
|   |                               | */s/ Mark A. Maki* |   |
|   |                               | *Mark A. Maki* |
|   |                               | *Vice President, Finance* |
|   |                               | *(Duly Authorized Officer)* |
|   |                               |   |
|   |                               |
|   |                               | Date:  August 14, 2003 |
|        |                                    |  |  |  |  |  |  |

 

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